It has been known for several years that the yield of hydrocarbons, such as gas and petroleum, from wells can be increased by fracturing the formation containing such hydrocarbons in order stimulate the flow of these hydrocarbons in the well. Various formation fracturing procedures have been proposed and many are now used in fracturing operations. Among these procedures are treatments with various chemicals (usually acids in aqueous solutions), hydraulic fracturing in which liquids are injected into the formation under high pressure (usually with propping agents), explosive methods in which explosives are detonated within the formations to effect mechanical fracture, and combinations of these procedures.
Hydraulic fracturing, the fracturing process of the present invention, is well known in the industry. During a typical hydraulic fracturing operation, a slurry, containing a viscous base fluid and a solid particulate material usually referred to as a "proppant", is pumped down the well at sufficient pressure to fracture open the producing formation surrounding the well. Once a fracture has been created the pumping of the slurry is typically continued until a sufficient volume of the proppant has been carried by the slurry into the fracture. After a suitable time the pumping operation is stopped at which time the proppant residue will prop open the fracture in the formation, preventing it from closing. As a result of the fracture, trapped hydrocarbons are freed and the flow from the producing formation is increased thereby increasing the wells production. In addition to creating deep-penetrating reservoir fractures, the fracturing process is useful in overcoming wellbore damage, to aid in secondary operations and to assist in the injection or disposal of industrial waste material.
During the fracturing process, the fractures propagate throughout the formation. The vertical propagation of these fractures is of particular importance. Fracture height measurements enable well operators to determine the success of the fracturing operation and, if necessary, to optimize future treatments, for other wells in the field. In addition, fracture height information can aid in the diagnosis of post-well stimulation problems such as lower production rates or unfavorable water cuts. The fracture height data can indicate whether communication has been established between the producing formation and adjacent water or non-producing formation zones. Height measurements also provide a check on the accuracy of fracture design simulators used prior to the job to predict fracture geometry. Excessive fracture height implies that the fracture length is shorter than the design value.
As previously stated, one reason for monitoring the vertical propagation of a formation fracture is the concern of fracturing out of a defined hydrocarbon producing zone into an adjacent water-producing zone. When this occurs, water will flow into the hydrocarbon-producing zone and the wellbore. This situation results in a well that produces mainly water instead of the desired hydrocarbon. Furthermore, if there is still the desire to continue producing hydrocarbons from the well, operators must solve the serious problem of safely disposing the produced, but undesired water. Addressing the problems arising from an out of zone fracture will also add expenses to the operations. In addition, if the fracture propagates into an adjacent non-producing solid formation, the materials used to maintain a fracture after the fluid pressure has decreased may be wasted in areas outside the objective formation area. In short, it is potentially dangerous and extremely costly to save a well that has been fractured out of the of the hydrocarbon zone.
Because of the serious problems that can occur as a result of out of zone fractures, it is desirable to monitor formation fracture movements. There are several techniques and devices used for monitoring and evaluating formation fracture movements such as radio-active tracers in the fracturing fluid, temperature logs, borehole televiewers, passive acoustics and gamma-ray logging. Most techniques provide some direct estimates of fractured zone height at the wellbore. However, fracture height determination away from the well is based on inferences.
One process used to monitor formation fractures employs radio-active tracers. In this process, fracturing fluid containing a radio-active tracer is injected into the formation to create and extend the fractures. When these radio-active fluid and proppant tracers are used, post fracture gamma-ray logs have shown higher levels of activity opposite where the tracer was deposited, thereby enabling operators to monitor the progress of the fractures.
Another common approach for determining fracture height uses temperature and gamma-ray logs. Temperature logs made before and after stimulation are compared to define an interval cooled by injection of the fracturing fluid and thus provide an estimate of the fractured zone. However, this technique is subject to limitations and ambiguities. For example, the temperature log may be difficult to interpret because of low temperature contrast, flowback from the formation before and after the treatment, or fluid movement behind the borehole casing.
Another approach using a borehole televiewer is limited in that it can only be used for fracture height evaluation in open holes. Acoustical methods are hampered by inhomogeneous formation impedance and/or the need for pumping while the tool is in the hole.
In addition to the specific problems associated with each type of monitoring, there are inherent problems in the present formation fracturing technology. During the fracturing process, fracture fluid is generally pumped into the formation at extremely high pressure, to force open the fractures, and an increasing proportion of sand is added to the fluid to prop open the resulting fractures. One problem with the existing technology is that the methods for determining whether a formation has been fractured out of the production zone rely on post-treatment (after the fracture has occurred) measurements. In such systems, a fracturing treatment is performed, the treatment is stopped, the well is tested and the data is analyzed. Moreover, with most known detection systems, the wait for post-fracturing data can take a considerable amount of time, even up to several days, which can delay the completion operations, resulting in higher personnel and operating costs. None of the logging tools or methods are capable of detecting the propagation of fractures in real time (during the injection of fluid).
Another problem associated with existing post-process "logging" or measuring devices is that the cost associated with interrupting a fracturing job in order to take a measurement of a fracture is not practical or feasible. Because fracture fluid is pumped into a formation under high pressures during the fracturing process, temporarily halting the pumping and fracturing operation will relieve the fluid pressure which could lead to undesirable results such as the closing of the fractures, thereby causing the reversal of fluid flow back into the borehole, or the build-up of sand in the hole. In addition, after taking measurements and completing the logging process, operators cannot restart the pumping equipment at the point of the fracturing process immediately before the interruption. Instead, the operators would have to repeat the complete fracturing job at additional cost and with unpredictable results. Furthermore, it may even be impossible or impractical to repeat the job.
As a result, the present formation fracturing technology is not reliable because operators must make preliminary estimates of and guesses at the length of the fracturing job, the rate of increase of sand concentration into the formation fracture and other fracture process factors. Existing measurement methods are limited to a retrospective view of the fracturing job, and only after the possible occurrence of damage.
A real-time monitoring system could address the above described problems and would allow well operators to monitor the fracturing process, to control fracture dimensions and to efficiently place higher concentrations of sand proppants in a desired formation location. In addition, if there is information that a fracture is close to extending out of a desired zone, operators can terminate the fracturing job immediately. Furthermore, real-time analysis of the ongoing treatment procedure will enable an operator to determine when it is necessary to pump greater concentrations of said proppant, depending on factors such as the vertical and lateral proximity of oil/water contacts with respect to the wellbore, the presence or absence of water-producing formations and horizontal changes in the physical properties of the reservoir rock.
This real-time monitoring system could be implemented using radio-active tracers in the fracturing fluid. As previously described, as the fracturing fluid progresses through the formation fracture, gamma-rays from the tracer element are detected and give an indication of the location of the fracture in the formation. However, even these real-time methods have to overcome obstacles. One such obstacle is distinguishing tracer element gamma-rays from gamma-rays from other sources.
One solution for distinguishing borehole activity from formation fracture activity is described in U.S. Pat. No. 4,731,531 to Handke, which describes a technique of inserting into borehole a tracer material that is non-radioactive. The material will not be activated until just before it is injected into the formation. With this technique, there is little borehole activity, therefore, only the formation fracture activity will be detected. However, there are questions and concerns about the ability to energize the non-radio-active material to a radio-active level that will produce gamma-rays with sufficient energy to be detected at the wellbore.
Another approach is described in U.S. Pat. No. 3,784,828 to Hayes, wherein two radiation detectors of different sensitivities respond to a radioactive tracer that has been discharged into the formation at the well depth of interest. This technique shows a radioactive tracer technique for distinguishing vertically flowing liquids in formation fractures from flows through passageways in the cement annulus between the steel casing and the borehole wall. If the tracer material moves in a vertical direction with respect to the injection depth, relatively high gamma-ray count rates from both detectors indicate that the tracer is flowing vertically through a fracture in the cement. Whereas, a relatively low count rate in the less sensitive detector, indicates that the vertical flow is taking place away from the casing and at some depth within the formation. Once again, this procedure does not address the problem of distinguishing tracer elements from gamma-rays from other sources. Because of the configuration of the tool and the operation of the technique, this invention does not encounter the problem of having to distinguish gamma-rays from various sources.
In U.S. Pat. Nos. 4,415,805 (Fertl et al.) and 4,861,986 (Arnold) distinctions are made using several different radioactive tracer elements. In Fertl, multiple stage fractures use different radioactive tracer elements injected into the well during each stage of the fracturing operation. After completion of the fracturing operation, the well is logged using natural gamma-ray logging. In Arnold, different isotopes are simultaneously injected and each isotope is detected by a detector which detects a specific energy range. Again, these techniques are not designed to address the problems which are of concern to the present invention.
Therefore, a real-time formation fracture monitoring system is needed in order to permit formation fracturing without encountering the above-mentioned problems.